The production of fluids from subterranean formations may include the use of subterranean wells to transport the fluids from the subterranean formation to a surface region and/or to provide stimulant fluids to the subterranean formation. These subterranean wells may be created using a drilling assembly to drill, or create, a wellbore, which may form a portion of the subterranean well. Drilling assemblies may include a plurality of portions, regions, components, parts, segments, and/or sections, each of which may serve a specific purpose during creation of the wellbore. These sections may include a cross-sectional area, and this cross-sectional area may vary from section to section and/or within sections.
As an illustrative, non-exclusive example, the drilling assembly may include a drill pipe and a bottom-hole assembly. The drill pipe typically will form a mechanical and fluid connection between the surface region and the bottom-hole assembly, a portion of which may be located at a terminal end of the drilling assembly. In addition, a cross-sectional area and/or a diameter of the drill pipe may be less than a cross-sectional area and/or diameter of the bottom-hole assembly.
The bottom-hole assembly, which may include a drill bit, may be in mechanical contact with a terminal end of the wellbore. During the drilling process, the drill bit may remove material, which may be referred to herein as cuttings, from the terminal end of the wellbore to increase a length of the wellbore. The drilling assembly may include and/or be a fluid conduit that is configured to provide a drilling fluid stream to the wellbore, such as to the terminal end thereof, via the bottom-hole assembly. The drilling fluid stream may lubricate at least a portion of the bottom-hole assembly, cool at least a portion of the bottom-hole assembly, and/or provide a motive force for removal of at least a portion of the cuttings from the wellbore by flowing the cuttings to the surface region.
However, a portion of the cuttings may remain within the wellbore. These cuttings may settle and/or otherwise accumulate and may produce a cuttings bed on and/or near a bottom surface of the wellbore. The size, or extent, of this cuttings bed, or, alternatively, a fraction of the cuttings that remain within the wellbore to form the cuttings bed, may vary with a variety of factors. Illustrative, non-exclusive examples of such factors may include a flow rate of the drilling fluid stream, a diameter of the wellbore, a diameter of the drilling assembly, a size of the cuttings, a density of the cuttings, a viscosity of the drilling fluid, and/or an orientation of the wellbore.
As an illustrative, non-exclusive example, a horizontal, or substantially horizontal, or highly inclined wellbore may include a larger cuttings bed than a vertical, or substantially vertical, wellbore. This may be caused, at least in part, by a tendency for the cuttings to settle under the influence of gravity to the bottom, or other horizontal, or substantially horizontal, or highly inclined surface of the wellbore and/or a tendency for the drilling fluid to flow, or channel, near an upper surface of the wellbore. As another illustrative, non-exclusive example, a wellbore that includes a breakout region, wherein a cross-sectional area of the wellbore is greater than a nominal cross-sectional area of the wellbore, may include a larger cuttings bed in the vicinity of the breakout region. This may be caused by a decrease in the flow rate of the cuttings fluid stream within the breakout region due to larger cross-sectional area of the wellbore in the breakout region.
During and/or after completion of the drilling process, at least a portion of the drilling assembly may be withdrawn from, drawn out of, pulled from, taken out of, and/or otherwise removed from the wellbore. This removal may include drawing, or pulling, the drilling assembly within the wellbore and along a longitudinal axis of the drilling assembly toward the surface region. In conjunction with pulling, the drilling assembly may be rotated and/or drilling fluid may be circulated through the drill bit and up the annulus. Removal of the drilling assembly from the wellbore may push, move, and/or otherwise collect at least a portion of the cuttings bed present within the wellbore, leading to the formation of a cuttings dune. As an illustrative, non-exclusive example, a transition region between a first section of the drilling assembly, which includes a first cross-sectional area, and a second section of the drilling assembly, which includes a second cross-sectional area that is larger than the first cross-sectional area, may facilitate, or otherwise contribute to, formation of the cuttings dune.
Under certain circumstances, the cuttings dune may cause a packoff, which may preclude further removal of the drilling assembly from the wellbore. The formation or occurrence of a packoff (including a packoff or a packoff-related event) may result in abandonment of at least a portion of the wellbore, require drilling a new section of the wellbore adjacent to the packoff location, and/or result in abandonment of the bottom whole assembly in the packoff region of the wellbore, any of which may substantially increase the costs associated with and/or time needed to complete the drilling operation.